1. Field of the Invention
This invention is directed to methods for determining the in situ strengths, pore pressures, elastic properties and formation stresses, of low permeability rocks such as shales and for determining desired parameters for fluids used in drilling wellbores.
2. Description of Related Art
Subsurface formations encountered in oil and gas drilling are compacted under in situ stresses due to overburden weight, tectonic effects, confinement and pore pressure. When a hole is drilled in a formation, the wellbore rock is subjected to increased shear stresses due to a reduction in confinement at the wallbore face by removal of the rock from the hole. compressive failure of the rock near the wellbore will occur if the rock does not have sufficient strength to support the increased shear stresses imposed upon it. However, if the hole is filled with drilling fluid with sufficient density (mud weight) to increase the wellbore pressure or confining pressure to a proper level, the shear stresses imposed on the wellbore rock will be reduced and the hole will remain stable. If the wellbore pressure is increased too much, lost circulation or hydraulic fracturing of the formation will occur as a result of tensile failure of the wellbore rock.
Classical elastic and elasto-plastic theories, failure criteria and fracture mechanics have been applied to model wellbore behavior under different stress conditions. An elastic model has been used with stress, pore pressure and empirically derived rock strength values to predict wellbore behavior. One of the present inventors has modeled the behavior of high angle wells in the North Sea by using classical theories and stress, pore pressure and empirically derived shale strength data from several of the early wells. The model results provided wellbore stability charts that showed the proper wellbore pressures or equivalent drilling mud weights or densities required to prevent wellbore collapse and lost circulation as a function of hole angle and depth. The wellbore stability charts were used as engineering guidelines for subsequent wells and saved many millions of dollars by reducing trouble costs due to wellbore failure. Examples of the wellbore stability charts for 0, 45 and 60 degree wells are given in FIG. 1. However, these drilling guidelines were developed at the expense of many stuck pipe incidents and other wellbore stability-related hole problems. Many millions of dollars of drilling trouble costs were spent before the rock strengths were determined empirically. This example and subsequent cases showed that if shale strength data were available a wellbore model could be used on initial wells in an area to diagnose and predict wellbore behavior and to prevent expensive stuck pipe problems and high trouble costs. Others recognized the importance of this approach and emphasized the need for shale strength data.
Some shales at great depths can be overcompacted and show peak stress behavior during triaxial tests. Complete stress-strain measurements past the peak stress to residual or ultimate stresses were obtained under pore pressure equilibrium conditions for each of several low permeability shales. An example of complete stress-strain curves for a low permeability shale is given in FIG. 2. Failure criteria or shear strength versus mean effective stress relationships were determined for the shales for both peak stress and residual or ultimate stress. An example of a failure criterion for a low permeability shale is shown in FIG. 3. This mean effective stress and strength relationship is frequently referred to as a Drucker-Pager model or an extended Von Mises criterion. Other failure relationships could also be used, e.g. Mohr-Coulomb and critical state.
The total specific surface area of a shale has been interpreted to be a quantitative measure of the hydratable surfaces present in the shale and an indicator of the hydratable clays present in the rock. The presence of hydratable clays affect the mechanical properties of the rock. One of the co-inventors of the present invention used the total specific surface area (or specific surface) as a means to classify different types of shales since it was found that in general those with high surface areas tended to be weak rocks (under similar stress environments) that produced wellbore failure under low to moderate stress conditions and that low surface area shales tended to be much stronger rocks.
In addition, one of the co-inventors found an empirical relationship that showed that shales with higher surface areas required higher concentrations of chemical inhibitors, e.g. potassium ions, in a drilling fluid to minimize shale hydration and weakening of the formation. The empirical surface area-inhibitor concentration relationship has been used to determine the optimum inhibitor, e.g. potassium chloride concentration required in a drilling fluid to minimize hydration and weakening of a shale formation with a certain surface area.